Controlling the Pressure within an Annular Volume of a Wellbore

ABSTRACT

A process is described for replacing at least a portion of the liquid within the annular volume of a casing system within a wellbore with a second liquid. The second liquid is preselected to provide a measure of control of the pressure within the annular volume as the fluid within the volume is being heated.

This application is a divisional of U.S. application Ser. No.12/249,852, filed Oct. 10, 2008, which is a divisional of U.S.application Ser. No. 11/282,424, filed on Nov. 18, 2005, the contents ofboth of which are hereby incorporated by reference in their entirety.U.S. application Ser. Nos. 12/641,257 and 12/641,272 are co-pendingdivisional applications of U.S. application Ser. No. 12/249,852, thecontents of which are also hereby incorporated by reference in theirentirety.

This application was made with government support under Contract No.W-7405-ENG-36 awarded by the U.S. Department of Energy. The governmenthas certain rights in the invention.

BACKGROUND OF THE INVENTION

The present invention relates to a method for controlling the pressuregenerated by a fluid contained within a confined volume while the fluidwithin the volume is being heated. In a preferred embodiment, thepresent invention relates to a process for controlling the pressurewithin the annular volume described by a casing string assembly within awellbore.

During the process of drilling a wellbore, such as an oil well,individual lengths of relatively large diameter metal tubulars aretypically secured together to form a casing string or liner that ispositioned within each section of the wellbore. Each of the casingstrings may be hung from a wellhead installation near the surface.Alternatively, some of the casing strings may be in the form of linerstrings that extend from near the setting depth of a previous section ofcasing. In this case, the liner string will be suspended from theprevious section of casing on a liner hanger. The casing strings areusually comprised of a number of joints or segments, each being on theorder of forty feet long, connected to one another by threadedconnections or other connection means. These connections are typicallymetal pipes, but may also be non-metal materials such as compositetubing. This casing string is used to increase the integrity of thewellbore by preventing the wall of the hole from caving in. In addition,the casing string prevents movement of fluids from one formation toanother formation through which the wellbore passes.

Conventionally, each section of the casing string is cemented within thewellbore before the next section of the wellbore is drilled.Accordingly, each subsequent section of the wellbore must have adiameter that is less than the previous section. For example, a firstsection of the wellbore may receive a surface (or conductor) casingstring having a 20-inch diameter. The next several sections of thewellbore may receive intermediate (or protection) casing strings having16-inch, 13⅜-inch and 9⅝-inch diameters, respectively. The finalsections of the wellbore may receive production casing strings having7-inch and 4½-inch diameters, respectively. When the cementing operationis completed and the cement sets, there is a column of cement in theannulus described by the outside surface of each casing string.

Subterranean zones penetrated by well bores are commonly sealed byhydraulic cement compositions. In this application, pipe strings such ascasings and liners are cemented in well bores using hydraulic cementcompositions. In performing these primary cementing operations, ahydraulic cement composition is pumped into the annular space describedby the walls of a well bore and the exterior surfaces of a pipe stringdisposed therein. The cement composition is permitted to set in theannular space to form an annular sheath of hardened substantiallyimpermeable cement which supports and positions the pipe string in thewell bore and seals the exterior surfaces of the pipe string to thewalls of the well bore. Hydraulic cement compositions are also utilizedin a variety of other cementing operations, such as sealing highlypermeable zones or fractures in subterranean zones, plugging cracks orholes in pipe strings and the like.

Casing assemblies comprising more than one casing string describe one ormore annular volumes between adjacent concentric casing strings withinthe wellbore. Normally, each annular volume is filled, at least to someextent, with the fluid which is present in the wellbore when the casingstring is installed. In a deep well, the quantities of fluid within theannular volume (i.e. the annular fluid) may be significant. Each annulus1 inch thick by 5000 feet long would contain roughly 50,000 gallons,depending on the diameter of the casing string.

In oil and gas wells it is not uncommon that a section of formation mustbe isolated from the rest of the well. This is typically achieved bybringing the top of the cement column from the subsequent string upinside the annulus above the previous casing shoe. While this isolatesthe formation, bringing the cement up inside the casing shoe effectivelyblocks the safety valve provided by nature's fracture gradient. Insteadof leaking off at the shoe, any pressure buildup will be exerted on thecasing, unless it can be bled off at the surface. Most land wells andsome offshore platform wells are equipped with wellheads that provideaccess to every casing annulus and an observed pressure increase can bequickly bled off. On the other hand, most subsea wellhead installationsdo not provide access to the casing annuli and a sealed annulus may becreated. Because the annulus is sealed, the internal pressure canincrease significantly in reaction to an increase in temperature.

The fluids in the annular volume during installation of the casingstrings will generally be at or near the ambient temperature of theseafloor. When the annular fluid is heated, it expands and a substantialpressure increase may result. This condition is commonly present in allproducing wells, but is most evident in deep water wells. Deep waterwells are likely to be vulnerable to annular pressure buildup because ofthe cold temperature of the displaced fluid, in contrast to elevatedtemperature of the production fluid during production. The temperatureof the fluid in the annular volume when it is sealed will generally bethe ambient temperature, which may be in the range of from 0° F. to 100°F. (for example 34° F.), with the lower temperatures occurring mostfrequently in subsea wells with a considerable depth of water above thewell. During production from the reservoir, produced fluids pass throughthe production tubing at significantly higher temperatures. Temperaturesin the range of 50° F. to 300° F. are expected, and temperatures in therange of 125° F. to 250° F. are frequently encountered.

The relatively high temperature of the produced fluids increases thetemperature of the annular fluid between the casing strings, andincreases the pressure against each of the casing strings. Conventionalliquids which are used in the annular volume expand with temperature atconstant pressure; in the constant volume of the annular space, theincreased fluid temperature results in significant pressure increases.Aqueous fluids, which are substantially incompressible, could increasein volume by upwards of 5% during the temperature change from ambientconditions to production conditions at constant pressure. At constantvolume, this increase in temperature may result in pressure increases upto on the order of 10,000 psig. The increased pressure significantlyincreases the chances that the casing string fails, with catastrophicconsequences to the operation of the well.

What is needed is a method for replacing at least a portion of theconventional fluid within the annular volume with a fluid system whichdecreases in specific volume as temperature of the fluid is increased.

The annular pressure buildup (APB) problem is well known in thepetroleum drilling/recovery industry. See: B. Moe and P. Erpelding,“Annular pressure buildup: What it is and what to do about it,”Deepwater Technology, p. 21-23, August (2000), and P. Oudeman and M.Kerem, “Transient behavior of annular pressure buildup in HP/HT wells,”J. of Petroleum Technology, v. 18, no. 3, p. 58-67 (2005). Severalpotential solutions have been previously reported: A. injection ofnitrogen-foamed cement spacers as described in R. F. Vargo, Jr., et.al., “Practical and Successful Prevention of Annular Pressure Buildup onthe Marlin Project,” Proceedings—SPE Annual Technical Conference andExhibition, p. 1235-1244, (2002), B. vacuum insulated tubing asdescribed in J. H. Azzola, et. al., “Application of Vacuum InsulatedTubing to Mitigate Annular Pressure Buildup,” Proceedings —SPE AnnualTechnical Conference and Exhibition, p. 1899-1905 (2004), C. crushablefoam spacer as described in C. P. Leach and A. J. Adams, “A New Methodfor the Relief of Annular Heat-up Pressure,” in proceedings,—SPE AnnualTechnical Conference and Exhibition, p. 819-826, (1993), D. cementshortfall, full-height cementation, preferred leak path or bleed port,enhanced casing (stronger), and use of compressible fluids as describedin R. Williamson et. al., “Control of Contained-Annulus Fluid PressureBuildup,” in proceedings, SPE/IADC Drilling Conference paper # 79875(2003), and E. use of a burst disk assembly, as described by J. Staudtin U.S. Pat. No. 6,457,528 (2002) and U.S. Pat. No. 6,675,898 (2004).These prior art examples, although potentially useful, do not providefull protection against the APB problem due to either difficulties inimplementation or prohibitory costs, or both. Our invention isrelatively easy to implement and cost effective.

SUMMARY OF THE INVENTION

Accordingly, a process is provided for controlling the pressure within aconfined volume, the process comprising:

-   -   a) providing a volume containing a first fluid having a first        pressure and a first temperature within the volume;    -   b) replacing at least a portion of the first fluid within the        volume with a second fluid;    -   c) sealing the volume to produce a confined volume;    -   d) heating the fluid within the confined volume, such that the        fluid is at a second pressure and at a second temperature,    -   wherein the second fluid is preselected such that the second        pressure is lower than had the confined volume contained the        first fluid only at the second temperature.

In a separate embodiment, a process is provided for controlling thepressure within the casing structure of a wellbore, wherein the pressuremay vary from location to location within the wellbore. In thisembodiment, the pressure and temperature relate to a single locationwithin the annular volume. Thus, the process comprises:

-   -   a) providing an annular volume described by two casing strings        within a wellbore and containing a first fluid having a first        pressure and a first temperature at a selected location within        the annular volume;    -   b) replacing at least a portion of the first fluid within the        annular volume with a second fluid;    -   c) sealing the annular volume to produce a confined volume;    -   d) heating the fluid within the confined volume, such that the        fluid at the selected location is at a second pressure and at a        second temperature,    -   wherein the second fluid is preselected such that the second        pressure at the selected location is lower than the pressure at        the selected location within the confined volume would have been        had the confined volume contained the first fluid only at the        second temperature.

In one embodiment, the second pressure, which occurs at a selectedlocation within the annular volume at a second temperature, is equal tothe first pressure at that location, in spite of an increasedtemperature of the fluid within the volume. In another embodiment, thesecond pressure at the selected location is no more than 50% higher,preferably no more than 30% higher and more preferably no more than 15%higher than the first pressure at the selected location.

In a separate embodiment, the process is directed to the maximumpressure within the annular volume. For an annular volume with asubstantial vertical length, the hydrostatic pressure generated by theannular fluid causes a pressure gradient through the vertical distance,with the pressure at the deepest location of the annular volume beinggreater than the pressure at the top of the wellbore, where locationsrelate to the earth's center. Thus, there is a location within theannular volume where the pressure is a maximum pressure. Therefore, inthis embodiment, a process is provided for controlling the maximumpressure within the casing structure of a wellbore, the processcomprising:

-   -   a) providing an annular volume described by two casings strings        within a wellbore and containing a first fluid having a first        maximum pressure at a first temperature within the annular        volume;    -   b) replacing at least a portion of the first fluid within the        annular volume with a second fluid;    -   c) sealing the annular volume to produce a confined volume; and    -   d) heating the fluid within the confined volume to an elevated        temperature relative to the first temperature, such that at        least a portion of the fluid is at a second maximum pressure;    -   wherein the second fluid is preselected such that the second        maximum pressure is lower than the maximum pressure within the        confined volume would have been had the confined volume        contained the first fluid only at the elevated temperature.

In one embodiment, the second maximum pressure within the annular volumeis equal to the first maximum pressure. In this embodiment, there is nonet pressure increase within the sealed annular volume, in spite of anelevated temperature of the fluid within the volume. In anotherembodiment, the second maximum pressure is no more than 50% higher,preferably no more than 30% higher and more preferably no more than 15%higher then the first maximum pressure.

In a further separate embodiment, a process is provided for controllingthe pressure within a confined volume, the process comprising:

-   -   a) providing a volume containing a first fluid and a second        fluid at a first pressure and at a first temperature;    -   b) sealing the volume to produce a confined volume;    -   c) heating the first fluid and the second fluid within the        confined volume, such that the first fluid and the second fluid        are at a second pressure and at a second temperature,    -   wherein the second fluid is preselected such that the second        pressure is lower than had the confined volume contained the        first fluid only at the second temperature.

In a particular embodiment, the second fluid comprises a monomer whichpolymerizes, with reduced volume, at a temperature and a pressure whichis in accordance with the conditions within the sealed annular volume.Accordingly, a process is provided for controlling the pressure within aconfined volume comprising:

-   -   a) providing a volume containing a first fluid, a portion of        which is at a first pressure and at a first temperature;    -   b) replacing at least a portion of the first fluid within the        volume with a second fluid;    -   c) sealing the volume to produce a confined volume;    -   d) heating the fluid within the confined volume, such that at        least a portion the fluid within the confined volume is at a        second pressure and at a second temperature,    -   wherein the second fluid comprises a monomer which polymerizes        at the second pressure and at a temperature in the range of        between the first temperature and the second temperature.

Among other factors, the present invention is based on the discovery offluid systems which have unusual thermal expansion properties, in thatthe fluids expand, at constant pressure, to a lesser extent than wouldbe expected for an incompressible fluid. Thus, when heated while beingconfined in a sealed volume, the fluids of the present invention cause alower pressure increase within the sealed volume than would be expectedfor a conventional fluid.

DESCRIPTION OF THE DRAWINGS

FIG. 1 illustrates an embodiment of the process of the invention,showing an open annular volume, during which time a second fluid isbeing added to the annular volume.

FIG. 2 illustrates an embodiment of the process of the invention,showing a sealed annular volume containing a second fluid at a secondtemperature and at a second pressure, as disclosed herein.

FIG. 3 illustrates an experimental result from testing one embodiment ofthe invention.

FIG. 4 illustrates an experimental result from testing one embodiment ofthe invention.

DETAILED DESCRIPTION OF THE INVENTION

The present invention provides a fluid system which, when heated withina confined volume, increases in pressure to a lower value than that of aconventional system. The confined volume is sealed to prevent escape ofthe fluid. Accordingly, the present invention provides a fluid and amethod for reducing the effect of a pressure increase within a sealed orconfined volume when the fluid within the volume is heated to anelevated temperature.

In one embodiment, the volume may be any fluid-containing volume whichis sealed and then heated. A non-limiting example of a volume of thisinvention is a reaction vessel, for performing, for example, chemicalreactions. The volume, initially filled with the first fluid, is open,meaning that a fluid can be made to pass into and out of the volume.Prior to the volume being sealed, a second fluid is made to pass intothe volume, replacing at least a portion of the first fluid in thevolume. This volume is then sealed to prevent further flow of fluid intoand out of the volume, and the fluid within the volume is heated. Suchheating causes the pressure to increase to a substantial extent withinthe volume, particularly with liquid phase fluids, and more particularlywith liquid phase fluids which are substantially incompressible. Theinvention therefore provides a second fluid having the property suchthat, when contained within the sealed volume and heated to a targettemperature, the pressure within the volume is less than the pressurewould be if the volume contained the first fluid only.

In a particular embodiment, the invention provides a process forcontrolling pressures within a wellbore, and particularly within anannular volume within a casing assembly which has been installed in awellbore, intended, for example, for removing a resource from areservoir. Examples of resources include crude oil, natural gas liquids,petroleum vapors (e.g. natural gas), synthesis gas (e.g. carbonmonoxide), other gases (e.g. carbon dioxide, nitrogen), and water oraqueous solutions.

A casing assembly comprises casing strings for protecting the sides ofthe wellbore which is formed by drilling into the earth. The annularvolume is bounded by two adjacent concentric casing strings within thecasing assembly. During construction of oil and gas wells, a rotarydrill is typically used to bore through subterranean formations of theearth to form the wellbore. As the rotary drill bores through the earth,a drilling fluid, known in the industry as a “mud,” is circulatedthrough the wellbore. The mud is usually pumped from the surface throughthe interior of the drill pipe. By continuously pumping the drillingfluid through the drill pipe, the drilling fluid can be circulated outthe bottom of the drill pipe and back up to the well surface through theannular space between the wall of the wellbore and the drill pipe. Themud is usually returned to the surface when certain geologicalinformation is desired and when the mud is to be recirculated. The mudis used to help lubricate and cool the drill bit and facilitates theremoval of cuttings as the wellbore is drilled. Also, the hydrostaticpressure created by the column of mud in the hole prevents blowoutswhich would otherwise occur due to the high pressures encountered withinthe wellbore. To prevent a blowout caused by the high pressure, heavyweight is put into the mud so the mud has a hydrostatic pressure greaterthan any pressure anticipated in the drilling.

Different types of mud must be used at different depths because pressureincreases in the wellbore with increasing depth of the wellbore. Forexample, the pressure at 2,500 ft. is much higher than the pressure at1,000 ft. The mud used at 1,000 ft. would not be heavy enough to use ata depth of 2,500 ft. and a blowout may occur. The weight of the mud atthe extreme depths in subsea wells must be particularly heavy tocounteract the high pressure. However, the hydrostatic pressure of thisparticularly heavy mud may cause the mud to start encroaching or leakinginto the formation, creating a loss of circulation of the mud. Casingstrings are used to line the wellbore to prevent leakage of the drillingmud.

To enable the use of different types of mud, different strings of casingare employed to eliminate the wide pressure gradient found in thewellbore. To start, the wellbore is drilled using a light mud to a depthwhere a heavier mud is required. This generally occurs at a little over1,000 ft. At this stage, a casing string is inserted into the wellbore.A cement slurry is pumped into the casing and a plug of fluid, such asdrilling mud or water, is pumped behind the cement slurry in order toforce the cement up into the annulus between the exterior of the casingand the interior of the wellbore. The amount of water used in formingthe cement slurry will vary over a wide range depending upon the type ofhydraulic cement selected, the required consistency of the slurry, thestrength requirement for a particular job, and the general jobconditions at hand.

Typically, hydraulic cements, particularly Portland cements, are used tocement the well casing within the wellbore. Hydraulic cements arecements which set and develop compressive strength due to the occurrenceof a hydration reaction which allows them to set or cure under water.The cement slurry is allowed to set and harden to hold the casing inplace. The cement also provides zonal isolation of the subsurfaceformations and helps to prevent sloughing or erosion of the wellbore.

After the first casing is set, the drilling continues until the wellboreis again drilled to a depth where a heavier mud is required and therequired heavier mud would start encroaching and leaking into theformation, generally at around 2,500 feet. Again, a casing string isinserted into the wellbore inside the previously installed string, and acement slurry is added as before.

Multiple casing strings may also be used in the wellbore to isolate twoor more formations which should not communicate with one another. Forexample, a unique feature found in the Gulf of Mexico is a high pressurefresh water sand that flows at a depth of about 2,000 feet. Due to thehigh pressure, an extra casing string is generally required at thatlevel. Otherwise, the sand would leak into the mud or production fluid.

A subsea wellhead typically has an outer housing secured to the seafloor and an inner wellhead housing received within the outer wellheadhousing. During the completion of an offshore well, the casing andtubing hangers are lowered into supported positions within the wellheadhousing through a BOP stack installed above the housing. Followingcompletion of the well, the BOP stack is replaced by a Christmas treehaving suitable valves for controlling the production of well fluids.The casing hanger is sealed off with respect to the housing bore and thetubing hanger is sealed off with respect to the casing hanger or thehousing bore, so as to effectively form a fluid barrier in the annulusbetween the casing and tubing strings and the bore of the housing abovethe tubing hanger. After the casing hanger is positioned and sealed off,a casing annulus seal is installed for pressure control. If the seal ison a surface well head, often the seal can have a port that communicateswith the casing annulus. However, in a subsea wellhead housing, there isa large diameter low pressure housing and a smaller diameter highpressure housing. Because of the high pressure, the high pressurehousing must be free of any ports for safety. Once the high pressurehousing is sealed off, there is no way to have a hole below the casinghanger for blowout prevention purposes.

Representatively illustrated in FIG. 1 is a method which embodiesprinciples of the present invention. In the following description of themethod and other apparatus and methods described herein, directionalterms, such as “above”, “below”, “upper”, “lower”, etc., are used onlyfor convenience in referring to the accompanying drawings. Additionally,it is to be understood that the various embodiments of the presentinvention described herein may be utilized in various orientations, suchas inclined, inverted, horizontal, vertical, etc., and in variousconfigurations, without departing from the principles of the presentinvention. The process described herein is applicable to wellbores inlanded sites and in underwater sites. It should be understood that thewellbore terminates at one end where the wellbore enters the earth. Inthe case of underwater sites, the terminus is at the water/earthinterface.

It should be understood that use of the terms “wellbore” and “casingstring” herein are not to be taken as limiting the invention to theparticular illustrated elements of the methods. The wellbore could beany wellbore, such as a branch of another wellbore, and does notnecessarily extent directly to the earth's surface. The casing stringcould be any type of tubular string, such as a liner string, etc. Theterms “casing string” and “linear string” are used herein to indicatetubular strings of any type, such as segmented or un-segmented tubularstrings, tubular strings made of any materials, including nonmetalmaterials, etc. Thus, the reader will appreciate that these and otherdescriptive terms used herein are merely for convenience in clearlyexplaining the illustrated embodiments of the invention, and are notused for limiting the scope of the invention.

FIG. 1 illustrates an embodiment of the invention. A wellbore 10 hasalready been drilled using drill string 50, and a casing assembly 20,comprising at least two casing strings in a concentric arrangement withrespect to each other, has been previously installed. The drill rig,with supporting means for supporting the drill string, for installingthe casing strings, and for supplying the fluids to the wellbore, is notshown. In FIG. 1, casing string 22 has been installed, and is sealed ator near one end against the wellbore 10 by a cement plug 24.

Particular attention is now directed to casing string 40, which has beeninstalled to extend to wellbore terminus 34. It is clear that terminus34 may be a temporary terminus, such that the wellbore may be extendedfurther after casing string 40 has been installed. Alternatively, casingstring 40 may extend to the ultimate depth in formation 5, and thewellbore will not be extended before production commences. An annularvolume 42, described by the inside surface of casing string 22 and theoutside surface of casing string 40, is filled with a fluid, andgenerally filled with the fluid which is present within the wellborevolume 36 when casing string 40 is installed. Conventional fluids whichmay initially be present in the annular volume include a drilling fluidor a completion fluid, depending on the circumstances of the drillingoperation. The properties of the fluid initially within the annularvolume, herein termed the first fluid, is selected to meet the needs ofthe wellbore drilling practitioner for drilling to complete the well. Inan embodiment, the first fluid is an incompressible fluid, using theconventional definition.

At the stage in the process illustrated in FIG. 1, the annular volume 42is in fluid communication with the wellbore volume 36 via the opening 44at one end of the casing. The other end of the annular volume,designated by 46, is in fluid communication with surface equipment, suchas a drilling rig, (not shown), which has the means for recovering afluid leaving the annular volume through 46. Environmental concernsprovide the incentive for minimizing the amount of fluid lost to theenvironment through 46.

In the process of the invention, a second fluid is introduced into thewellbore volume 36 through opening 48 to replace at least a portion ofthe first fluid in the annular volume 42. Opening 48 is in fluidcommunication with means for supplying the second fluid. Pumping meansfor this purpose may be located, for example, on a drilling rig or aproduction rig. The second fluid is supplied to the volume as a plug orpill, and passes downward through the wellbore volume 36 in relativelypure form. At the wellbore terminus 34, the second fluid enters theannular volume 42 through opening 44, and passes upward, driving thefirst fluid originally in the annular volume 42 ahead of the secondfluid pill, and out of the annular volume through opening 46. The amountof the second fluid which is supplied to the annular volume is a matterof engineering choice, depending on the amount of pressure which can betolerated inside the sealed annular volume 42. This amount is furtherinfluence by, for example, the size of the well system, the temperatureof the second fluid when it is supplied to the annular volume, thetemperature of the fluids which will be produced in the well, expectedtemperature of the fluid in the annular volume during production, designand specifications of the casing string and the like.

After a sufficient amount of the second fluid has been added to annularvolume 42 to replace at least a portion of the first fluid containedtherein, the annular volume 42 is sealed. FIG. 2 illustrates the annularvolume 42 sealed by a concrete plug at 26, and by the casing annulusplug, shown at 28. Generally, the casing annulus seal seals the top ofthe wellbore, preventing escape of fluids from the wellbore into theenvironment. Thus, the sealed, or confined, volume represented by theannular volume 42 of the casing strings contains a fluid, which isconfined in place and prevented from leaking from the volume to anynoticeable extent.

In the embodiment illustrated in FIG. 2, at least a portion of a firstfluid contained within a volume such as an annular volume 42, and havinga first pressure and a first temperature within the volume, is replacedwith a second fluid, such that the volume is filled with the combinationof the first fluid and the second fluid. The annular volume 42, betweenthe casing strings 22 and 40, is sealed by concrete plug 26 and bycasing annulus plug 28. The temperature of the fluid within the annularvolume 42, comprising the second fluid, is generally within the range of0°-100° F. For subsea installations, the fluid temperature (ie. thefirst temperature) is often less than 60° F., or less than 40° F., or,for example, in the temperature range between 25° F. and 35° F.

When hydrocarbon fluids begin to be produced and to flow up throughproduction conduit 52 and out of the wellbore 10, these fluids aregenerally at a higher temperature than the first temperature. Productionfluid temperatures in the range of 50° F. to 300° F. are expected, andtemperatures in the range of 125° F. to 250° F. are frequentlyencountered. The relatively hotter production fluids within conduit 52heat the fluid within the confined annular volume 42, such that thefluid is at a second pressure and at a second temperature. Inconventional systems, the fluid pressure within the sealed annularvolume would begin to increase to a significantly higher pressure as thetemperature increases. In contrast, according to the present invention,the second fluid is preselected such that the second pressure within theconfined volume, after the temperature of the fluid within the volume isincreased to the second temperature, is lower than had the confinedvolume contained the first fluid only at the second temperature.

The benefits and advantages derived from practice of the invention arecontrasted with the deficiencies of the conventional process. Theannular volume is initially filled with a first fluid. The temperatureof the first fluid may be at ambient temperature or below, depending onthe condition of the wellbore during addition of the first fluid. Forsubsea wellbores, the first fluid may be cooled by the water throughwhich the first fluid passes enroute from the source at the drillingplatform to the wellbore. Under these conditions, the first fluid willgenerally be at a temperature in the range of 0° F. to 100° F. Forsubsea installations, the fluid temperature (ie. the first temperature)is often less than 60° F., or less than 40° F., or, for example, in thetemperature range between 25° F. and 35° F. After the fluid is sealedwithin the annular volume, it is heated by the production fluids passingupward through the production tubing 52 in the wellbore; the increasedtemperature conventionally results in an increase in pressure, sometimesup to catastrophic levels.

Annular Pressure

In contrast, this pressure within the annular volume is controlled tomanageable levels by the present process. In the practice of theinvention, a confined volume which contains a fluid is heated, such thatthe fluid within the confined volume is at a second pressure and at asecond temperature. In one embodiment, the second pressure is uniformthroughout the confined volume. In another embodiment, the secondpressure may vary from place to place within the volume. In thisembodiment, therefore, the second pressure (and second temperature) isreferenced to a particular location, termed the selected location,within the annular volume. For example, the annular volume within thecasing assembly in a wellbore can have a vertical extent of hundreds,and even thousands, of feet. The hydrostatic pressure within thefluid-filled wellbore is thus expected to be higher at the bottom of thewellbore than at its top. In another embodiment, therefore, the presentprocess is directed to controlling the maximum pressure within theannular volume, taking account of the hydrostatic head and other factorswithin the volume.

For purposes of this disclosure, the target pressure is the desiredpressure within the annular volume during the practice of the presentinvention. In one embodiment, the target pressure in the practice of theinvention is a second pressure which is lower than had the confinedvolume contained the first fluid only. In another embodiment, the secondpressure is equal to the first pressure within the annular volume. Inanother embodiment, the second fluid is preselected such that the secondpressure of the second fluid contained within the sealed annular volumeat the second temperature is no more than 50% higher, preferably no morethan 30% higher, and more preferably no more than 15% higher than thefirst pressure of the unsealed annular volume at a first temperature andcontaining the first fluid only.

In many cases, the first pressure, the first temperature, the secondpressure and the second temperature may be measured and the quantitativevalue of each may be known. It will be recognized by the skilledpractitioner, however, that the invention may be practiced in itsentirety without knowledge of the quantitative values of theseparameters. It is sufficient for the practice of the invention that thesecond pressure be maintained below the pressure limit at which theintegrity of the container (e.g. the casing string) in which the fluidis contained will be compromised to an unacceptable extent.

Second Fluid System

As used herein, the fluid which is added to the annular volume tocontrol the pressure within the annular volume is termed the secondfluid or, in the alternative, the annular fluid. As such, the secondfluid has thermal expansion properties which cause a lower pressureincrease within the annular volume than would be expected for asubstantially incompressible liquid. The fluid which is present in thewellbore volume 36 during installation of the casing string 40, andtherefore the fluid which is initially within the annular volume 42 whenthe casing string is installed, is termed the first fluid. Thecomposition of the first fluid is not critical for the invention, andwill generally be one of various fluids used in drilling and completingthe well, including, for example, a drilling fluid or a completionfluid. Drilling fluids may be water or oil based, and may furthercomprise surfactants, salts, weighting agents and any other materialswhich are needed for effective cooling of the drill bit, removal ofcuttings, and protection and conditioning of the wellbore for fluidproduction. Likewise, completion fluids may be water or oil based, andmay further comprise materials for cleaning the wellbore and installedstructures in preparation for recovery of fluids from the formation.

In the practice of the invention, the first fluid within the annularvolume is replaced, at least in part, by a second fluid. In general, thesecond fluid comprises a liquid component and an additional componentwhich contributes to the desired properties as described herein. In oneembodiment, the second fluid is an incompressible fluid. In a separateembodiment, the combination of the first fluid and the second fluid isan incompressible fluid, using the conventional meaning. The liquidcomponent may comprise water, hydrocarbons or both, including, forexample, one or more components of a drilling fluid. Aqueous solutionscontaining dissolved organic and/or inorganic salts, acids or bases maybe included in the second fluid system. Hydrocarbon mixtures, includingmaterials typically found in drilling fluids or completion fluids may beincluded. Examples include diesel fuel, C₆ to C₂₀ mixtures, alcohols,aldehydes, ketones, ethers, carbonyls, aromatics, paraffins andcycloparaffins. Emulsions with a continuous aqueous phase and adiscontinuous organic phase may be included; alternatively, emulsionswith a continuous organic phase and a discontinuous aqueous phase may beincluded. Further, the second fluid may include a liquid phase as thecontinuous phase, and further include solids, which may be present as aslurry or as massive particles. Or, the second fluid may comprise aliquid as a continuous phase, either layered with a vapor phase, orcontaining a vapor phase in the form of bubbles within the liquid. Inanother embodiment, the second fluid comprises liquid, vapor and solidphases, in any or all of the forms described above. In each alternative,the second fluid has unexpected expansion properties with respect to anincrease in temperature of the fluid.

Anhydrous Inorganic Materials

In one embodiment, the second fluid comprises anhydrous inorganicmaterials, in an aqueous-containing carrier fluid. The addition ofanhydrous inorganic crystals or materials into the annular volumeabsorbs the excess water into their structure, and alleviates theannular pressure problem. For example, each formula quantity ofanhydrous calcium sulfate (including industrial versions, such as gypsumand plaster-of-paris) absorbs 10 waters of hydration into itscrystalline structure. Also effective are inorganic compounds such asbarium oxide or calcium oxide, which also absorb water. Aluminosilicatematerials, including crystalline aluminosilicates such as zeolites,dehydrate liquids by trapping water at the molecular level. Examplezeolites for this application are 3A, 4A, 13X and Y zeolite. Thesezeolites do not expand upon hydration, and, in fact, release air duringthe process. Any air released during hydration will be introduced intothe confined annular volume. Since air is compressible, the air pocketdeveloped by the hydrating zeolites provides a pressure buffer as thefluid in the annular volume is heated.

In a preferred embodiment of the invention, pellets of a water absorbinginorganic compound may be encapsulated with any material that can slowlydissolve in the trapped fluid, such as a slowly soluble polymer, so thatthe reaction can be delayed enough to provide circulation time beforethe absorbent action occurs. This could also work in binary or ternarysystems where water is a small component of the mixture that is trapped(e.g., 6% water, balance as mineral oil or other such admixture).Non-limiting examples of a slowly soluble polymer includepoly(vinylalcohol), carboxymethyl cellulose and gelatin.

In a separate embodiment, at least a portion of the inorganic materialssupplied to the annular volume in the second fluid comprises a zirconiumtungstate or a zirconium molybdate having a negative coefficient ofthermal expansion.

Cross-Linked Polymeric Materials

In a separate embodiment, one or more cross-linked organic/polymericmaterials are included in the annular fluid of this invention tocounteract the increase in pressure as the annular fluid is heatedwithin the sealed volume. Any dimensionally stable open porous foammaterial (e.g. polystyrene foam and polyurethane foam) can be suitablyused for this purpose. The effectiveness of the polymeric material forcounteracting the effect of increasing pressure is enhanced when coatedwith a slowly soluble polymer. In this way, the polymeric materialcoated with the slowly soluble polymer is introduced to the annularvolume. Following cementing, the slowly soluble polymer dissolves,exposing the cross-linked polymer to the annular fluid. Increasing thepressure causes the cross-linked polymer to crush, which both reducesthe pressure within the annular volume, and dislodges the vapor whichwas originally trapped within the cross-linked polymer. Both thecrushing of the polymer and the generation of a compressible gascontributes to the decrease in pressure within the annular volume.

Polymerization System

In a separate embodiment, a process is provided for controlling thepressure within a confined volume by providing a second fluid comprisinga monomer which polymerizes with a reduction in specific volume at thesecond pressure and at a temperature in the range of between the firsttemperature to the second temperature. According to this embodiment, thepressure within the sealed annular volume is decreased on heating by thepolymerization of a monomer which is added to the annular fluid prior tosealing the volume. Both a water soluble monomer and a water insolublemonomer, when added to the annular volume, can polymerize, with anaccompanying decrease in volume (and associated decrease in pressurewithin the annular volume). Such a decrease in volume would, in theconfined volume of the sealed annulus, result in a decrease in pressure,within the confined volume, relative to a similar system withoutpolymerization of the particular monomers of the present invention.

The monomer of the invention may be mixed with water, with oil, or witha more complex mixture characteristic of a drilling mud, including highdensity components in the preparation of the second fluid. The monomerwill be present in the second fluid in the range of 1 to 99 vol %, morepreferably in the range of 5 to 75 vol %, still more preferably in therange of 10 to 50 vol %. An example second fluid comprises 20 vol % ofthe monomer and 80 vol % of a second component comprising water and ahigh density material such as barium sulfate.

With polymerization of monomers, including polymerization of acrylates,such as methyl acrylate and methyl methacrylate, as much as a 25%reduction in volume between the liquid monomer and solid polymer canresult from the polymerization process. See, for example, “Acrylic andMethacrylic Ester Polymers”, in Encyclopedia of Polymer Science andEngineering, 2nd Edition, J. Kroschwitz, ed., John Wiley & Sons, Inc.,Volume 1, Table 20, p. 266, (1985), and D. A. Tildbrook, at. al,“Prediction of Polymerization Shrinkage Using Molecular Modeling,” J.Poly. Sci; Part B: Polymer Physics, 41, 528-548 (2003). In a preferredembodiment of this invention, the monomer is suspended or emulsified(using soap) in water as a water/oil mixture with appropriatepolymerization initiator(s), pumped into the annular space, and aftercementation, polymerization occurs (again, taking advantage of slowkinetics at the nearly freezing temperature), with a total volumedecrease of up to 5% can be achieved with a 20% vol/vol mixture ofmonomer and water. Non-limiting examples of other vinyl monomers thatcould be practical for this in-situ polymerization process include otheracrylic esters, methacrylic esters, butadiene, styrene, vinyl chloride,N-vinylpyrrolidone, N-vinylcaprolactam, or other such oil and/or watersoluble monomers.

Additional benefits can be derived from the choice of initiator for thepolymerization process. An azo-type initiator produces nitrogen gas as aby-product during the polymerization process. The resulting gas phasecomponent which is generated in the confined annular volume, being acompressible fluid, can contribute to the control of the pressure withinthe confined annular volume as the annular fluid is being heated by theproduct fluid passing through the production tubing. A peroxideinitiator may also be used, depending on the temperature and chemicalconstraints of the product fluid. Alternatively, a redox initiatorsystem such as ammonium persulfate and the activatorN,N,N′N′-tetramethylethylenediamine, or potassium persulfate and theactivator ferrous sulfate/sodium bisulfite could also be used ifencapsulated as mentioned above to control the timing of when thepolymerization occurs.

Gas Generating Material

In another embodiment, the addition of a gas generating materialprovides a compressible gas pocket that alleviates the annular pressureproblem. An example of a gas generating material useful for theinvention comprises combining citric acid and bicarbonate, in a 1:2weight ratio, with a small amount of witch hazel extract, into amoldable product which evolves carbon dioxide gas when hydrated withwater. Preferably, pellets of this material are coated and/orencapsulated with a slowly water soluble polymer, as described above. Inusing these pellets in the practice of the invention, the coated pelletsare pumped into the annular volume, which is then sealed as described.The “timed release” of the pellets generates evolved gas, which istrapped at the upper levels in the annular volume.

Binary Fluid System

In another embodiment, the second fluid system is a binary fluid systemcomprising two liquids which have a negative blending volumecoefficient. By a negative blending volume coefficient is meant havingthe property which, when the two liquids are blended together, thevolume of blended liquid is less than the sum of the volumes of the twoliquids prior to blending. Example fluids with this particular propertyinclude a blend of alcohol with an aqueous fluid. Example alcoholsinclude C₁ to C₈ alcohols; preferred alcohols are methanol, ethanol,propanol and butanol. In this case, the aqueous fluid may be thedrilling fluid which is present in the annular volume followinginstallation of the casing string.

It is important to maintain the alcohol as a separate phase until theannular volume is sealed, as described, before forming the blend withthe second liquid. In one embodiment, the alcohol is pumped into theannular volume as a relatively pure plug; with the major mixing of thealcohol phase with the aqueous phase occurring within the annular volumeafter the annular volume is sealed. Alternatively, the alcohol isencapsulated with any material that can slowly dissolve in the trappedfluid, such as a slowly soluble polymer, so that the mixing of the twophases can be delayed enough to ensure that mixing occurs after thevolume is sealed. Non-limiting examples of a slowly soluble polymerinclude poly(vinylalcohol), carboxymethyl cellulose and gelatin.

Thus, prior to or during heating of the annular volume during productionof the hot fluids, the slowly soluble polymer is dissolved and thealcohol phase mixes with the aqueous phase, resulting in a reduction inpressure within the annular volume relative to the pressure which wouldhave been present had the alcohol phase not been added as described. Incarrying out this embodiment, an alcohol phase is added up to 90%,preferably in the range of 5 vol % to 80 vol %, more preferably in therange of 10 vol % to 50 vol % of the total volume of the liquid in theannular volume, the specific amount depending on the specificapplication.

EXAMPLE

Laboratory experiments demonstrated an effective reduction in volume ofa mixture of methyl methacrylate in an emulsion polymerization process,and by example below, the process was proven to work in an apparatuswhich holds volume constant, while monitoring pressure during a heatingcycle (Example 1), and in a field experiment using a 500 foot test well(Example 2).

Example 1

A pressure bomb was filled with an aqueous fluid at 200 psig startingpressure. The bomb was then sealed to prevent escape of fluids from thebomb, and heated from 24° C. to 100° C. As shown in FIG. 3, the pressureof the fluid within the bomb increased to 14,000 psig during the heatingcycle.

The pressure bomb used above was filled with an aqueous emulsion fluidcontaining a 20% volume loading of methyl methacrylate (with azo-typeinitiator) at 200 psig starting pressure. The bomb was then sealed toprevent escape of fluids from the bomb, and heated from 24° C. to 100°C. As shown in FIG. 3, the pressure of the fluid within the bombincreased to approximately 3000 psig, but at a lower rate of increasethan with the aqueous fluid alone. At approximately 70° C.,polymerization of the methyl methacrylate monomer was initiated, and thepressure within the bomb decreased to below the initial pressure withinthe bomb.

Example 2

A scaled up field experiment was also performed. Water was used in a 500foot deep test well within an annular space confined by 7 inch and 9⅝inch casings. After placement of the fluid, the annular space waspre-pressurized to 500 psig, and then heated by circulating hot waterinside the 7 inch pipe. Over a period of 2 hours, the temperature inputwas 190 F, and a temperature out of 160 F (due to the down-holeformation absorbing heat). The resulting pressure was about 2100 psig(FIG. 4).

A similar emulsion fluid as described in Example 1, containing 20%volume loading of methyl methacrylate (with azo-type initiator) was usedin the same test well. Within several minutes after the initial 500pre-pressurization, it was noted that the pressure had already droppedto zero, so the annulus was again pressurized up to 500 psig. Over aperiod of 2 hours, the temperature was elevated as before, and it wasnoted that the input and output temperatures were virtually identicaldue to the heat generated by the polymerization reaction. The pressureagain decreased to zero, and then slowly increased to a final stablepressure of 240 psig (FIG. 4). The significant drop in pressure was dueto the shrinkage of the monomer to polymer. Samples collected at the endof the experiment were analyzed for monomer and polymer. There wasevidence of a trace amount of monomer (<1%), and the polymer had aweight-average molecular weight of nearly 3 million.

1. A process for controlling the pressure within a confined volumecomprising: providing a volume containing a first fluid having a firstpressure and a first temperature within the volume; replacing at least aportion of the first fluid within the volume with a second fluidcomprising a porous foam material; sealing the volume to produce aconfined volume; heating the fluid within the confined volume, such thatthe fluid is at a second pressure and at a second temperature; whereinthe second fluid is preselected such that the second pressure is lowerthan had the confined volume contained the first fluid only at thesecond temperature.
 2. The process according to claim 1 wherein thevolume is an annular volume.
 3. The process according to claim 1 whereinthe annular volume is described by two concentric casing strings withina wellbore.
 4. The process according to claim 1, wherein the firsttemperature is in the range of from 0° F. to 100° F.
 5. The processaccording to claim 1, wherein the second temperature is in the range of50° F. to 300° F.
 6. The process according to claim 5, wherein thesecond temperature is in the range of 125° F. to 250° F.
 7. The processaccording to claim 1, wherein the fluid within the confined volume ofstep (c) is at the first pressure and at the first temperature.
 8. Theprocess according to claim 1, wherein the first pressure is the maximumpressure of the first fluid within the volume of step (a), and whereinthe second pressure is the maximum pressure of the fluid within thevolume of step (d).
 9. The process according to claim 1, wherein thefirst pressure of the fluid at the first temperature within the volumeof step (a) is at a selected location within the volume, and whereinsecond pressure of the fluid at the second temperature within the volumeof step (d) is at the selected location within the volume. 10.-14.(canceled)
 15. The process according to claim 1, wherein the porous foammaterial is selected from the group consisting of polystyrene andpolyurethane foam.
 16. The process according to claim 1, wherein theporous foam material is encapsulated in a slowly soluble polymer.17.-29. (canceled)
 30. A process for controlling the pressure within thecasing structure of a wellbore, comprising: a) providing an annularvolume described by two casing strings within a wellbore and containinga first fluid having a first pressure and a first temperature at aselected location within the annular volume; b) replacing at least aportion of the first fluid within the annular volume with a second fluidcomprising a porous foam material; c) sealing the annular volume toproduce a confined volume; d) heating the fluid within the confinedvolume, such that the fluid at the selected location is at a secondpressure and at a second temperature; wherein the second fluid ispreselected such that the second pressure at the selected location islower than the pressure at the selected location within the confinedvolume would have been had the confined volume contained the first fluidonly at the second temperature.
 31. The process according to claim 30,wherein the second pressure is no more than 50% higher than the firstpressure.
 32. The process according to claim 30, wherein the secondpressure is no more than 30% higher than the first pressure.
 33. Theprocess according to claim 30, wherein the second pressure is no morethan 15% higher than the first pressure.
 34. The process according toclaim 30, wherein the second pressure is equal to the first pressure.35. A process for controlling the pressure within the casing structureof a wellbore, comprising: a) providing an annular volume described bytwo casing strings within a wellbore and containing a first fluid havinga first maximum pressure at a first temperature within the annularvolume; b) replacing at least a portion of the first fluid within theannular volume with a second fluid comprising a porous foam material; c)sealing the annular volume to produce a confined volume; d) heating thefluid within the confined volume to an elevated temperature relative tothe first temperature, such that at least a portion of the fluid is at asecond maximum pressure; wherein the second fluid is preselected suchthat the second maximum pressure is lower than the maximum pressurewithin the confined volume would have been had the confined volumecontained the first fluid only at the elevated temperature.
 36. Aprocess for controlling the pressure within a confined volumecomprising: a) providing at a first pressure and at a first temperaturea volume containing a first fluid and a second fluid comprising a porousfoam material; b) sealing the volume to produce a confined volume; c)heating the first fluid and the second fluid within the confined volume,such that the first fluid and the second fluid are at a second pressureand at a second temperature; wherein the second fluid is preselectedsuch that the second pressure is lower than had the confined volumecontained the first fluid only at the second temperature. 37.-42.(canceled)